Retainer packer valve system



Dec. 23, 1969 4 J. w. KISLING m 3,485,298

RETAINER PACKER VALVE SYSTEM Original Filed Oct. 5, 1967 3 Sheets-Sheet1 c/'meJ W Kath/733E INVENTOR.

ATTORNEY Dec. 23, 1969 J. w. KISLING m 3,485,298

RETAINER PACKER VALVE SYSTEM Original Filed Oct. 5, 1967 3 Sheets-Sheet2 (127/77 9: W Hub/7y, Z7

INVENTOR.

ATTORNEY Dec. 23, 1969 J- W. KISLING lll RETAINER PACKER VALVE SYSTEMOriginal Filed Oct. 5, 1967 3 Sheets-Sheet 3 l/l/I/Y Jame-u W lflJ/lfly,E

INVENTOR.

ATTORNEY United States Patent 3,485,298 RETAINER PACKER VALVE SYSTEMJames W. Kisling III, Houston, Tex., assignor to Schlumberger TechnologyCorporation, Houston, Tex., a corporation of Texas Original applicationOct. 5, 1967, Ser. No. 673,190. Divided and this application Dec. 16,1968, Ser. No. 800,022 Int. Cl. E2113 43/00, 23/00, 33/12, 33/13, 49/00US. Cl. 166226 1 Claim ABSTRACT OF THE DISCLOSURE The particularembodiment described herein as illustrative of one form of the inventionis a well packer having a body with anchor and packing means to providean anchored pack off in a Well bore. The body has a flow passage whichcan be selectively opened and closed by a valve sleeve which is mountedfor rotational movement in the flow passage between positions openingand closing same. Valve actuating means coupled to a running-in stringis extendible into the flow passage and is coupled to valve sleeve forrotating it. Coengageable means between the actuating means and body isarranged to rotate the actuating means and thus the valve sleeve betweenopen and closed positions in response to upward and downward movement ofthe running-in string.

This is a division of application Ser. No. 673,190, filed Oct. 5, 1967.

This invention relates generally to well packers, and more specificallyto a new and improved well packer apparatus having a valve system forproviding controlled fluid communication through the well packerapparatus.

It is often desirable in connection with wells to seal olt the well borewhile providing controlled fluid communication to a well zone below thesealing point. For example, it may be desirable to squeeze cement belowa packer through a pipe string at a predetermined point behind liner orcasing. Such an operation is advantageous in preventing communicationwith other zones, closing channels, etc., before a particular zone isput on production. Or, it may be desirable to repezforate a well zone,and cement is squeezed to close old perforations. Further, it might bedesirable to abandon a Well zone and cement may be used to squeeze offthe zone.

In any event, an apparatus commonly known as a cement or squeezeretainer packer may be used to isolate the zone which is to bepressurized from well fluids in the remainder of the well bore. Suchpackers have valving which can be closed after squeezing is completed inorder to retain the cement below the packer at developed pressures.Commonly, such valving has taken the form of check valve type systemswhich readily permit fluid flow into the isolated zone from the pipestring but which prevent reverse flow. Check type valves, however, whilefunctioning to hold the back pressure of the squeeze, aredisadvantageous because such systems do not prevent loss of mud to theformation when low break-down pressures are encountered, do not keepannulus fluids ofi weak formations when the pipe string is removed, anddo not permit the use of batch squeeze operations. Moreover, in order tocompletely b;idge the well bore against fluid flow in either directionsafter a cementing operation has been completed, a shut-oi? plug or thelike must be placed in the packer bore.

In view of the foregoing disadvantages in using check type valve systemsin cement retainer packers, various so called pressure balanced valvesystems have come into usage. Such valve systems, usually beingconstituted by a reciprocating sleeve which is opened and closedmechanically, will hold fluid pressure from above or below and thusalleviate most of the foregoing problems. However, prior systems havenot been reliable and simple to operate and have been subject tomalfunctions due to failures in closing when it is desired to hold backpressure, or due to inability to subsequently reopen the valve foradditional displacement. In view of the great depths at which suchpackers and valve systems may be used, and the extremely high pressureswhich are sometimes developed, it is important that the structureutilized be as sturdy, foolproof and simple in operation as is possiblein view of the circumstances.

The present invention provides a new and improved well packer and valvesystem which has all the advantages of pressure balanced systems. Thevalve system comprises a rotating sleeve which will hold pressure fromeither direction when closed and which is mechanically actuated in apositive manner in response to simple upward and downward motion of thepipe string. Moreover, the valve system of the present invention isstructurally arranged to be unaffected by well environments which havecontributed to malfunctions in prior systems, and is thus highlyreliable in operation in a well bore.

The present invention may be summarized to further point out the variousconcepts involved, as a well packer apparatus having normally retractedslips and packing which can be expanded to provide an anchored pack offin a well bore. When set, the packer isolates the well bore therebelow.The mandrel of the packer apparatus has a flow passage which is portedto the side of the mandrel below the packing. Valve means is providedfor opening and closing the flow passage, the valve means comprising asleeve which is mounted adjacent the side ports for rotation betweenpositions opening and closing the flow passage. To rotate the valvesleeve, actuating means coupled to the pipe string extends into the flowpassage and is co-rotatively coupled to the valve sleeve. Coengageablemeans between the mandrel and actuating means is arranged to causepredetermined rotational movement of the valve sleeve between open andclosed positions in response to upward and downward motion of the pipestring at the top of the well bore. Thus it will be apparent that thepresent invention provides a new and improved retainer packer apparatushaving a valve system which is mechanically operated in a simple manner,and the valve system is arranged to be unresponsive to fluid pressurefrom above or below.

The present invention has other concepts and advantages which willbecome more clearly apparent in connection with the following detaileddescription. A preferred embodiment is shown in the accompanyingdrawings, in which:

FIGURES 1A and 1B are longitudinal sectional views, with portions inside elevation, of the present invention with parts in relativepositions for lowering into a well bore, FIGURE 13 forming a lowercontinuation of FIGURE 1A;

FIGURE 2 is an isometric view of the rotary valve element;

FIGURE 3 is a fragmentary developed view of a coupling mechanism inaccordance with the present invention;

FIGURE 4 is a fragmentary developed view to illus trate the torquetransmission structure between the extension and valve sleeve;

FIGURE 5 is a fragmentary developed view of the extension slot system inaccordance with the present invention;

FIGURE 6 is a cross section on line 66 of FIGURE 1A; and

FIGURES 7A and 7B are view similar to FIGURES 1A and 1B except withparts of the present invention in their cooperative positions when setin a well bore.

With initial reference to FIGURES 1A and 1B, apparatus which willillustrate the principles of the present invention includes a mechanicalsetting tool A and a well packer B having a valve system C. The settingtool A is utilized in setting the packer B in a well bore so that thepacker B can function to pack otf the well bore. The valve system Ccontrols fluid communication to the well bore below the packer B. Theentire apparatus can be lowered into the well on a running-in string 10of tubing or drill pipe which provides a fluid conduit extending to thetop of the well, as well as a mechanical member which can be manipulatedat the top of the well bore to effect operation of the setting tool Aand the valve assembl C.

as shown in FIGURE 18, the packer B has a central body or mandrel 11having a bore 12 which provides a fluid passageway and further has alower guide portion 13 which supports lower slips 14. The slips 14 cantake any desired form, such as fragnible, segmented, or integralexpansible type slips. A lower expander cone 15 is arranged to shift thelower slips 14 outwardly and a conventional packing structure 16surrounds the mandrel 11 between the lower expander cone and an upperexpander cone 17. Typical anti-extrusion rings 18, 18a can confine theend portions of the packing 16, and shear pins 19, 19a or other suitablemeans can releasably couple the expander cones 15 and 17 to the mandrel11 to control the relative motion sequence between parts in any desiredmanner. A conventional split ratchet ring 20 is arranged between theupper expander cone 17 and the mandrel 11 and cooperates with externalteeth 21 on the mandrel to trap compression loading in the packingstructure 16 when the well packer B is set.

The lower guide portion 13 of the mandrel 11 is constituted as a valvebody having a central flow passage 24 which is closed in a fluid tightmanner at its lower end by a plug 25. Diametrically opposed side ports26 in the valve body 13 are provided to communicate with the wellannulus below the packing element 16. A valve sleeve 27 is locatedwithin the passage 24 adjacent to the side ports 26 and is arranged formovement between various rotational positions about the longitudinalaxis of the mandrel 11 to control fluid flow from the passage 24 throughthe side ports 26. In one rotational position, lateral ports 28 in thevalve sleeve 27 are aligned with the side ports 26 in the valve body 23to permit fluid flow. In other rotation positions of the valve sleeve27, the ports 26 and 28 are not in registry and the passage 24 is closedto fluid flow in either direction.

As shown in FIGURE 2, the valve sleeve 27 is generally tubular in formand has appropriate external grooves for a seal structure which caninclude upper and lower annular seals 29 and 30 which are connected byvertically extending seals 31 and 32 located on either side of the ports28. With this type of seal configuration, the side seals 31 and 32together with the seal portions 33 and 34 above and below the ports 28prevent fluid flow through the ports, while the entirety of the upperand lower seals 29 and 3t} precludes flow through the body ports 26. Inthe alternative, it will be appreciated that the seal arrangement couldinclude face seals which surround the sleeve ports 28 to prevent flow ineither direction through the sleeve ports, along with upper and lowerannular sleeve seals above and below the face seals to prevent flow ineither direction through the body ports 26. Radially inwardly extendingpins 35 on the valve sleeve 27 provide a means for applying rotationforce or torque to the valve sleeve 27 to rotate it between its variouspositions.

With particular reference to FIGURE 1A, the setting tool assembly Aincludes a central operating mandrel 38 having an open bore 39 and whichcan be connected to the lower end of the tubing string 10 by a threadedcollar 40 or the like. The lower end portion of the operating mandrel 38is provided with a swivel connection 41 to a tubular extension assemblywhich includes an enlarged sub 42 arranged to engage the upper end ofthe packer mandrel 11 and a tubular extension which telescopes withinthe bore 13 of the packer mandrel. The sub 42 and extension 45 arethreaded together at 43 in a fluid tight manner. A swivel sleeve 44 iscoupled to the upper portion of the sub 42 and has an inwardly extendingshoulder section 46 forming an annular space 47 which rotatably receivedan outwardly extending section 48 on the operating mandrel 38.Accordingly, it will be apparent that the extension 45 and sub 42 canturn or rotate relative to both the operating mandrel 38 and the tubing10. Appropriate seals such as O-rings 49 and 50 can be provided, thelower seal 50 preventing fluid leakage from the bore of the mandrel 38at the swivel connection 41, and the upper seal 49 protecting the swivelconnection from ambient well fluids and debris.

The extension 45 is telescoped within the bore of the packer mandrel 11and has arcuate coupling lugs 52 which can engage Within an elongateinternal mandrel recess 53. The recess 53, shown in an inside developedview in FIGURE 3, is open to the top of the packer mandrel 11 byvertically extending slots 54 and located on circumferentially oppositesides of the bore of the mandrel. Thus, the coupling lugs 52 can beinserted into the recess 53 via the slots 54 and 55 and rotation of theextension 45 relative to the mandrel 11 will position the lugs 52underneath mandrel shoulders 56 formed between the slots. With thisrelationship of parts, en gagement of the coupling lugs 52 with theshoulders 56 will limit upward movement of the extension 45 relative tothe mandrel 11, and engagement of the sub 42 with the upper end surfaceof the mandrel 11 will limit downward movement. Accordingly, when thelugs 52 are underneath the shoulders 56, the extension 45 is coupled forlimited reciprocating motion relative to the mandrel 11, and when thelugs are aligned with the slots 54, 55, the extension can be insertedwithin, or withdrawn from, the bore 12 of the mandrel 11.

The lower end of the extension 45 is open at 57 and side ports 58 areprovided for fluid flow. When the extension 45 is telescoped within thepacker mandrel 11 as shown in FIGURE 1B, the lower end portion 59 of ofthe extension 45 is located within the valve sleeve 27. A torque sleeve60 is threaded onto the lower end portion 59, and properly positionedthereon as by a screw 61 or the like, and has upwardly extending sideguide slots 62 which are flared and open at the lower end of the sleeve60. The slots 62 receive the valve sleeve pins 35 so that rotation ofthe extension 45 will impart corresponding rotation to the valve sleeve27. Each of the side slots 62, one of which is shown in developed viewin FIGURE 4, has a longitudinal portion 63 of sufficient vertical extentwhereby the extension 45 can be moved upwardly and downwardly apredetermined amount and still be co-rotatively coupled to the valvesleeve 27. Moreover, the slots 60 each have an upper circumferentiallyenlarged portion 64 to permit the valve sleeve 27 to be rotated to acertain extent relative to the extension 45 and in a direction which isopposite to its normal direction of rotation for purposes which will behereafter explained. The upper end of the torque sleeve 60 can be madeto terminate below an outwardly extending shoulder 65 on the extension45 to provide an annular recess in which a seal structure 66 is located.The seal structure 66, which can take many forms, is shown as one ormore metallic rings 67 having inner and outer grooves which receivesuitable seals 68 and 69. Thus arranged, the seal structure 66 preventsfluid leakage between the packer mandrel 11 and the extension 45 whenthe latter is telescoped within the former.

Upper slip segments 72 are mounted at the upper end portion of thepacker mandrel 11 adjacent to the upper expander cone 17. The segments72 have upwardly facing wickers or teeth 73 on their outer peripheries,as well as inner inclined surfaces 74 which are engageable with outerinclined surfaces 75 on the expander cone 17 for shifting the segmentsoutwardly into gripping engagement with the well casing. The extensionsub 42 and the packer mandrel 11 are respectively provided with annulargrooves 76 and 77 and the slip segments 72 can have correspondingshoulders 78 and 79 which engage within the grooves to limit verticalmovement of the slip segments in their retracted positions. A- retainersleeve 80, which forms a part of the setting tool A, extends downwardlyin encompassing relation over upper portions :51 of the slip segments toretain them inwardly as long as the retainer sleeve occupies therelative position shown in FIGURES 1A and 18. It will be appreciatedthat due to the engaging conditions of the shoulders 78 and 79 withinthe grooves 76 and 77, and to the holding action of the retainer sleeve80, the slip segments 72 are quite rigidly held inwardly in retractedpositions to prevent any likelihood of premature setting during loweringinto a well.

Further to the setting tool assembly A, a control sleeve 38 (FIGURE 1A)is slidably and co-rotatively secured to the operating mandrel 38 bysplines 89 or the like. The control sleeve 88 is initially locked in anupper position on the mandrel 38 by several latch lugs 90whieh engage ina mandrel detent 91. A drag mechanism 92 including a tubular cage 93 isinitially secured in a lower position on the control sleeve bycoengaging right-hand threads 94. Typical drag blocks 95 are carried bythe cage 93 and are urged outwardly by coil springs 96 to frictionallyengage casing and resist motion in a conventional manner. An innersurface 97 on the cage 93 holds the latch lugs 90 inwardly in engagementwith the mandrel detent 19 while the parts are in the relative positionsfor lowering into a well bore.

The slip retainer sleeve 80 extends downwardly from the cage 93 toencompass the upper end portions 81 of the upper slip segments 72 as waspreviously described. When desired, it will be appreciated thatright-hand rotation of the operating mandrel 38 by the running-in stringwill rotate the control sleeve 88 relative to the drag mechanism 92,and, due to the interengagement of the threads 94, cause the dragmechanism and the retainer sleeve 80 to feed upwardly along the controlsleeve 38, thereby removing the retainer sleeve from encompassingrelation to the upper portions of the slips 72. Upward feeding of thedrag mechanism 92 will also position an internal cage recess 100opposite the latch lugs 90 and permit them to move outwardly and releasefrom the mandrel detent 91, thereby, permitting upward movement of theoperating mandrel 38 relative to the control sleeve 88 and the dragmechanism 92.

A slip setting sleeve 101 extends downwardly from the control sleeve 88and terminates in spaced relation to the upper portions 81 of the slips72. When the retainer sleeve 80 is removed upwardly, the slips 72 arenot restrained and can move outwardly to engage the well casing. Outwardmovement of the slips will, of course, remove the shoulders 73 and 79from engagement with the mandrel and sub grooves 76 and 77 and therebyuncouple the packer mandrel 11 from the extension assembly. With thiscondition of parts, the extension 45 can telescope upwardly to thepacker mandrel 11 until the coupling lugs 52 engage the recess shoulders56. Then upward extension movement will shift the packer mandrel 11upwardly relative to the setting sleeve 101, the later part not movingupward by virtue of the engagement of the friction drag blocks 95 withthe well casing. Accordingly, it will be appreciated that the slipsegments 72 cannot move upwardly due to the holding action of thesetting sleeve 101, and that the expander cone 17 can be moved upwardlyand behind the slips 72 to shift them outwardly into firm anchoringengagement with the well casing. Once the upper slips 72 are set, theexpander cone 17 cannot move any further upwardly and continued movementof the manderl 11 will advance the lower cone toward the upper cone toexpand the packing 16. The lower slips 14 are shifted over the lowerexpander cone 15 and outwardly into gripping engagement with the wellcasing. The ratchet ring 20 will lock the parts in expanded position inconventional manner.

In response to upward and downward motions of the extension 45 relativeto the packer mandrel 11 occasioned by like motions imparted to therunning-in string 10 once the packer B is set, the extension 45 iscaused to rotate through various rotational positions due tointerengagement of index pins 104, extending inwardly within the bore ofthe mandrel 11, with an extension slot system 105 to be described below.Rotation of the extension 45 within the packer mandrel 11 serves theprimary function of selectively rotating the valve sleeve 27 betweenopen and closed positions. As shown in plain view in FIG- URE 5, theslot system 105 is formed about the periphery of extension 45 andincludes vertically disposed entrance and exit slots 106 and 107 locatedon opposite sides of the extension. Inasmuch as the slot system issymmetrically arranged around the circumference of the extension 45, forpurposes of brevity, only one-half of the total slot system structurewill be described and it will be appreciated that each slot portionmentioned hereafter has an identical counterpart location on theopposite side of the extension. Between these entrance and exit slots106 and 107 are upper pockets 108 and 109, the left upper pocket 108being located, for example, about 50 degrees from entrance and exit slot106 and the right upper pocket 109 being located, for example, about 40degrees from entrance and exit slot 107. An intermediate pocket 110 islocated between the upper pockets 108 and 109 and can be located about50 degrees from the left upper pocket 108. The entrance and exit slot106 is connected to the upper pocket 108 by a channel 111 which extendsupwardly and to the right, and the upper pocket 108 is connected to theintermediate pocket 110 by a channel 112 which extends downwardly and tothe right. The intermediate pocket 110 is connected to the upper pocket109 by a channel 113 which extends upwardly and to the right likechannel 111, and the upper pocket 109 is connected to the entrance andexit slot 107 by a channel 114 which extends downwardly and to the rightlike channel 112. The intersections of the channels 111 and 112, and 113and 114, are located somewhat to the left of the respective centers ofthe upper pockets 108 and 109 so that the index pin 104 is constrainedto enter the channel 112 when leaving pocket 103, and channel 114 whenleaving pocket 109. Moreover, the intersection of channels 112 and 113is located somewhat to the left of the intermediate pocket 110 so thatthe index pin 104 will enter the channel 113 when leaving the pocket110.

It will be apparent that the slot system 105 provides a guidcway inwhich the pins 104 engage to cause a predetermined sequence ofrotational movements of the extension 45 relative to the mandrel 11 inresponse to upward and downward motions of the extension. Thus, movementof the index pin 104 from entrance and exit slot 106 to the left upperpocket 108 will cause the extension 45 to rotate about 50 degrees in aclockwise direction (viewed from above) within the packer mandrel 11,such rotation being occasioned by engagement of the upper inclined wall115 of channel 111 with the index pin. Movement of the index pin 104from the upper pocket 108 to the pocket 110 will cause another 50degrees rotation of the extension 45 when the lower inclined wall 116 ofthe channel 112 engages the index pin 104, and further movement from thepocket 110 to the right upper pocket 109 will cause an additional 40degrees relative rotation when the index pin engages the upper inclinedwall 117 of the channel 113. Finally, movement of the index pin 104 fromthe right upper pocket 109 down through the channel 114 with inclinedlower wall 118 and out of the entrance and exit slot 107 will effectanother 40 degrees relative rotation of the extension 45 for a total of180 degrees. Each increment of extension rotation will cause acorresponding amount of rotation of the valve sleeve 27 by virtue ofengagement of the valve sleeve pins 35 with the walls 63a of the slots62 in the torque sleeve 60. Of course the direction of rotation of theextension 45 and the valve sleeve 27 is a function of the slot system105 and, although the arrangement shown is preferred, it will beappreciated that the slot system 105 could be arranged in reverse mannerso that the extension and valve will rotate in the lefthand direction.

The coupling lugs 52 on the extension 45 are vertically aligned relativeto the entrance and exit slots 106 and 107, and the mandrel recessopenings 54 and 55 (FIG- URE 3) aligned relative to the index pins 104,such that when the index pins 104 engage within the entrance and exitslots, the coupling lugs 52 are vertically aligned with the mandrelrecess openings and can readily pass into, and out of, the mandrelrecess 55. When the index pins 104 engage the upper wall surface 115 ofthe channels 111 which are inclined upwardly and to the right, theextension 45 is caused to rotate or swivel in the clockwise direction toposition the coupling lugs 52 underneath the mandrel shoulders 56. Thelugs 52 will remain in positions underneath the mandrel shoulders 56 aslong as the entrance and exit slots 106, 107 are not aligned with theindex pins 104. The entrance and exit slots 106 and 107 are alsocircumferentially located relative to the torque sleeve slots 60 so thatwhen the index pins 104 are within the slots 106 and 107, and thus whenthe coupling lugs 52 can pass through the recess openings 54 and 55, thevalve sleeve 27 is always in a closed rotational position. The bosses120 formed between the entrance and exit slots 106 and 107 can havelower converging cam surfaces 121 and 122 to insure that the mandrelindex pins 104 will enter one or the other of the slots 106 and 107regardless of the initial rotational position of the extension 45relative to the packer mandrel 11 when the extension is inserted.Moreover, the pins 104 can have flattened peripheral portions to reducebearing loads as the pins work within the slot system 105.

Should it ever be desirable to disconnect the setting tool A from thewell packer B, leaving the extension 45 Within the bore of the packermandrel 11, for example, where the extension 45 has become lodged withinthe mandrel by sedimentation or junk in the well, a safety feature isprovided for this purpose. With particular reference to FIGURES 1A and6, the swivel section 48 has a reduced diameter portion 125 which isexternally threaded with buttress type teeth 126 facing upwardly. Aclutch ring 127 is cut through at 129 and is capable of sufiicientlateral expansion and contraction for ratcheting action over the teeth126 in an upward direction. A longitudinally extending key 130 on theswivel sleeve 44 engages within the cut 129 to co-rotatively secure thering to the sleeve. The swivel section 48 further has an up peroutwardly extending annular shoulder 131 having an inwardly and upwardlyinclined lower face 132 which is shaped in complimentary manner to theupper end surface 133 of the clutch ring 127.

It will be appreciated that due to the configuration of the slot system105 and its coaction with the indexing pins 104, the extension 45 willalways rotate relative to operating mandrel 35 in the same direction,for example, with the slot arrangement shown in FIGURE 5, in theclockwise or right-hand direction viewed from above. Accordingly, thethreads 126 and 128 on the section 125 and clutch ring 127 respectivelycan be formed as right-hand threads. Thus, clockwise rotation of theswivel sleeve 44 and the clutch ring 127 relative to the operatingmandrel 38 will cause downward feeding of the clutch ring until it abutsthe sub shoulder 134 as shown in FIGURE lA whereupon the clutch ringwill remain stationary and merely ratchet over the threads 126 inresponse to continued rotation of extension assembly relative to theoperating mandrel during normal operation of the tool. However, if theoperating mandrel 38 is rotated in a clockwise or right-hand directionrelative to the extension assembly by right-hand rotation of therunning-in string 10 at the top of the well bore, the clutch ring 127will feed upwardly along the threads 126 until the inclined surfaces 132and 133 engage, thereby exerting inward force on the clutch ring andclutching the operating mandrel 38 to the swivel sleeve 44 since theclutch ring cannot ratchet downwardly along the threads 126. Then,continued rotation of the running-in string 10 will effect unscrewing ofthe threads 43 between the swivel sub 42 and the extension 45, whichthreads are formed as left-hand threads, so that the entire setting toolA except for the extension 45 can be withdrawn from the well.

OPERATION In operation, the parts are assembled as shown in the drawingswith the extension 45 telescoped within the packer mandrel 11. The slips15 and 72 and the packing 16 are in normally retracted positions, theupper slips 72 being retained inwardly by the retainer sleeve 80. Thedrag blocks 95 can slide along in frictional engagement with the wellcasing as the tool is lowered into a well bore to setting depth. If itis desired to lower the packer with the valve sleeve 27 in opencondition so that the running-in string 10 can fill with well fluidduring lowering, the extension 45 is merely inserted into the packermandrel 11 during assembly and the index pins 104 will properly indexthe extension until the pins are in the left upper pockets 108, orpositions D, FIGURE 5. This rotational position of the extension 45 willproperly align the sleeve and body ports 28 and 26 in registry with oneanother. On the other hand, to run the tool in the well with the valvesleeve 27 in closed condition, the plug 25 at the lower end of themandrel 11 can be conveniently removed to gain access to the valvesleeve 27 to position the pins 35 within the enlarged slot portions 64on the torque sleeve 60. This will orient the valve sleeve 27 in arotationally closed position. Inasmuch as the valve sleeve 27 is alwaysrotated in the same direction by the extension 45, the enlarged portions64 have no effect on the operation of the valve sleeve 27 after the wellpacker is set. In other words, the straight sides 63a of thelongitudinal slot portion 63 always engage the sleeve pins 35 to rotatethe valve sleeve.

When it is desired to set the packer B, the running-in string 10 isfirst rotated a number of turns to the right. Since the drag mechanism92 cannot rotate due to engagement of the drag blocks 95 with thecasing, the control sleeve 88 will be rotated relative to the dragmechanism 92 with resultant upward feeding of the retainer sleeve out ofencompassing relation to the upper portions 81 of the upper slips 72. Inactuality, the entire apparatus in the well except for the dragmechanism 92 and retainer sleeve 80 will be rotated by the running-instring 10. When the retainer sleeve 80 moves sufliciently upwardly, theslips 77 are free to move outwardly and the lower end of the settingsleeve 101 is cleared for engagement with upper end surfaces of theslips 72. The cage recess 100 is now positioned adjacent to the latchlugs so that the lugs can move outwardly and release from the mandreldetent 91. The operating mandrel 38 is thus free to be moved upwardlyrelative to the control sleeve 88, the drag mechanism 92 and the settingsleeve 101.

The running-in string 10 is then elevated to set the packer B. When theslips 72 are released, as previously described, the extension 45 canmove upwardly to a limited extent relative to the packer mandrel 11. Asthis relative movement occurs, the extension 45 is rotated as the indexpins 104 move within the intermediate pockets 110, or positions E,FIGURE 5. This rotation of the extension also positions the couplinglugs 52 underneath and in engagement with the mandrel recess shoulders56, the lugs moving from positions G to positions H as shown in FIGURE3. If the valve is initially open, rotation of the extension 45 willalso cause corresponding rotation of the valve sleeve 27 to closedposition. On the other hand, if the valve sleeve 27 is initially closedduring lowering, rotation of the extension 45 will have no effect on thevalve sleeve because the enlarged slot portions 64 in the torque sleeve60 will permit this extension rotation to occur without impartingcorresponding rotation to the valve sleeve. Thus, the valve sleeve 27will remain in closed position.

Inasmuch as the coupling lugs 52 are engaging the mandrel Shoulders 56,continued upward movement of the extension 45 will elevate the packermandrel 11, and thus the upper expander cone 17, toward the lower endsurface of the setting sleeve 101. The slips 72 will thus be shiftedoutwardly into gripping engagement with the casing, the holding force ofthe drag blocks 95 being transmitted through the cage 93, threads 94,control sleeve 88 to the setting sleeve 101 to prevent its upwardmovement. The slips 72 will accordingly be held against upward movementby the setting sleeve 101 and sufiicient upward movement of the packermandrel 11 will bring the expander cone 17 behind the slips 72 to shiftthem outwardly into gripping engagement with the casing as shown inFIGURE 7B. When the upper slips 72 grip the casing,- the upper expandercone 17 cannot move any further upwardly, and continued upward movementof the packer mandrel 11 will cause expansion of the packing element 16and then shifting of the lower slips 14 over the lower expander cone 15.The external body teeth 21 will ratchet through the ratchet ring 20 andthe ring will trap the mandrel 11 in the highest position to which it ismoved. Accordingly, the packing and slips are locked in expandedpositions and when a predetermined upward strain is taken on therunning-in string, the packer B will be firmly set.

After thus setting the packer B, the weight of the running-in string isslacked off. This will occasion downward movement of the extension 45within the packer mandrel 11 with consequent rotation of the extensionand the valve sleeve 27 until the index pins 104 are within the rightupper pockets 109 of the slot system, positions E in FIGURE 5. The valvesleeve 27 is still in one of its closed rotational positions.Accordingly, the running-in string 10 is closed-01f at its lower end andcan be pressure tested for leakage at this time. The weight of therunning-in string 10 can be conveniently imposed upon the packer B sothat pressurizing the string 10 will not cause the extension as to belifted upwardly by the pressure. The feature of being able to imposetubing weight on the tool when testing tubing is an important advantageover packers of this type having reciprocating sleeve valves because theimposition of tubing weight may open the valve systems of these packers.

After such testing, the running-in string 10 is simply picked up at thesurface to disengage the extension 45 from within the bore of the packermandrel 11. As the extension 45 is moved upwardly, the index pins 104will cause the extension and the valve sleeve 27 to rotate again as theindex pins move within the entrance and exit slots 107. The valve sleeve27 is still closed. In this relative rotational position of parts thecoupling lugs 52 are moved from positions K, FIGURE 3, into verticalalignment with the mandrel recess openings 54, 55. Accordingly, theextension 45 is conditioned to be withdrawn from the bore of the packermandrel 11. It will be noted that whenever the extension 45 iswithdrawn, the valve sleeve 27 is always left in a closed rotationalposition, whereby the well packer B completely bridges the well bore toprevent fluid flow in either longitudinal direction.

To perform a pressure operation such as squeeze cementing, the extension45 is reinserted within the bore 12 of the packer mandrel 11 by downwardmovement of the running-in string 10. Regardless of the initial randomrotational position of the extension 45, the bosses 120 and the lowercam surfaces 121 and 122 will c ooperate with the index pins 104 toproperly orient the extension 45 such that the index pins are verticallyaligned within the entrance and exit slots 106 and 107. With the slots106 and 107 thus aligned, the coupling lugs 52 are also aligned with themandrel recess openings 54, 55 and the side slots 62 in the valve torquesleeve 60 are properly positioned with respect to the valve sleeve pins35 so that the lower end portion 59 of the extension can be loweredinside the valve sleeve 27. When the extension 45 has moved sufiicientlydownwardly within the bore of the packer mandrel 11, the index pins 104will engage the upper inclined surfaces of the channels 111 and causethe extension and the valve sleeve 27 to rotate during further downwardmovement until the index pins are within the left upper pockets 108. Asthis rotation oiccurs, the valve sleeve ports 28 will become radiallyaligned with the valve body ports 26 to open the valve. The couplinglugs 52 are also rotated to positions within the mandrel recess 53 suchthat the lugs are underneath the recess shoulders 56. With the valveopen, cement slurry can be displaced through the runningin string 10 andout into the well bore below the packer.

When sufiicient displacement has occurred and it is desired to trap thesqueeze, e.g., to retain the cement slurry at developed pressures belowthe packer B, the valve sleeve 27 can be moved to a rotationally closedposition by simply picking the running-in string 10 upwardly to indexthe extension 45 until the index pins 104 are within the intermediatepockets 110, thereby rotating the valve sleeve 27 to closed position.The coupling lugs 52 will engage the mandrel shoulders 56 to positivelyprevent separation of the extension 45 from the mandrel 11, therebyenabling complete control of tubing and annulus pressures. Thus it willbe appreciated that adequate annulus pressures can be maintained toprevent dumping cement into well bore when the extension 45 is purposelydisengaged. The extension 45 can be withdrawn from the packer mandrel11, leaving the valve sleeve 27 in closed position, by imparting a pairof vertical motions to the running-in string 10, one downward, and oneupward. The corresponding reciprocation of the extension 45 will causethe index pins 104 to traverse the channels 113 and 114 and into theentrance and exit slots 106, whereupon the coupling lugs 52 arevertically aligned with the mandrel recess openings 54, 55 and theextension 45 is free for upward movement, leaving the valve sleeve 27 inclosed condition. The setting tool A can be withdrawn from the well, orconventional circulation or reverse circulation procedures can beundertaken. Of course, the extension 45 can be reinserted within thepacker mandrel 11 for further operations as desired.

Although the packer B is disclosed as settable on the mechanical settingtool A, it will be appreciated that the packer can be set by the variouswireline or other setting tools which are conventional in the art. Incase of wireline setting, of course other upper slips such asconventional frangible or solid type slips, can be utilized, and theplug 25 at the lower end of the mandrel 11 is provided with internalthreads for connecting to the tension member of the setting tool. Thusit will be apparent that apparatus of the present invention is quiteversatile and can be used for a variety of down hole applications aswill be appreciated by those skilled in this art,

A new and improved well packer and valve system have been disclosed foruse in a well bore. The valve system comprises a rotating sleeve whichis arranged to be unaffected fluid pressure acting in either direction.The packer can be set and the valve system operated in a convenient,positive, and reliable manner by a minimum number of manipulation of therunning-in string at the top of the well bore. Since certain changes ormodifications may be made in the present invention by those skilled inthe art Without departing from the concepts involved, it is intendedthat the appended claims cover all such changes or modifications fallingwithin the true spirit and scope of the present invention.

I claim:

1. A valve for use in a well bore comprising: valve body means having aflow passage and flow port extending through the wall thereof tocommunicate said passage with the Well bore outside said body means; avalve sleeve having port means and mounted for rotation within said bodymeans between positions opening and closing said flow port; actuatingmeans extending in said passage and arranged for coupling to anoperating member; means for slidably and co-rotatively coupling saidactuator means to said valve sleeve; and coengageable means between saidactuator means and valve body responsive to longitudinal motion of theoperating member for rotating said actuating means, thereby rotatingsaid valve sleeve between said open and closed positions.

References Cited UNITED STATES PATENTS 3,207,468 9/1965 Lauducci et al25158 3,351,133 11/1967 Clark et al. 1-66226 X 3,356,140 12/1967 Young166l28 3,386,701 6/1968 Potts 166226 3,433,304 3/1969 Paulas 166226DAVID H. BROWN, Primary Examiner US. Cl. X.R.

